Field of the Invention
The present invention concerns a system and a method for stimulating a well.
Prior and Related Art
As the term is used herein, a wellbore is a fully or partly cased borehole extending through layers in an underground geological structure, hereinafter a formation. A well is a borehole with equipment needed for its operation, e.g. for producing oil or gas from a reservoir, for producing geothermal energy or for injecting fluids for enhanced oil recovery or for storing CO2. The well may be placed onshore or offshore, and the invention is neither limited to any particular industry nor to the purpose of the well.
A well may extend more or less horizontally. For ease of explanation, the terms “upstream” and “uphole” are used herein for the direction toward the surface regardless of the actual direction of a fluid flow or the inclination of the wellbore. Similarly, “downstream” and “downhole” refer to the opposite direction, i.e. away from the surface.
Stimulating or treating a well means to improve its performance, typically by improving the fluid flow between the formation and wellbore. As used herein, stimulating a well, “stimulation” for short, involves increasing an injection pressure to force some agent, e.g. acid or a propping agent, into the formation, and reduce the pressure when the agent is injected. Hydraulic fracturing of a production well for hydrocarbons, i,e, oil and/or gas, will be used as a non-limiting example in the following.
In the oil and gas industry, a “zone” includes a layer containing hydrocarbons. In the present example, a casing is perforated at the zones. The “target zone” is the zone to be stimulated.
Hydraulic fracturing is performed by pumping a liquid into the formation at a pressure sufficient to create fractures in the formation. When the fracture is open, a propping agent is added to the liquid. The propping agent remains in the fractures to keep them open when the pumping rate, and hence the pressure, decreases.
The break-down pressure, i.e. the pressure required to create fractures in the formation, depends on the compressive pressure in, and the strength of, the formation. Thus, the break-down pressure and its associated injection rate vary significantly between applications. In the present example, the fractures would ideally be wings extending into the target zone, and a layer of impermeable rock above the porous layer containing oil or gas would prevent the fractures from extending. However, fractures, faults etc. already present in the formation will usually cause a tree-like fracture structure in the zone. In addition, fractures in the layers adjacent to the layer comprising hydrocarbons may widen and cause leakages and loss to formation.
Even when water is not lost to the formation, hydraulic fracturing consumes a significant amount of water. According to Arthur, J. D., “A Comparative Analysis of Hydraulic Fracturing and Underground Injection”, presented at the GWPC Water/Energy Symposium, Pittsburgh, Pa., Sep. 25-29, 2010, a water consumption of 1 000 to 20 000 bbl/day (119-2 400 m3/day) is common for onshore wells in the US. To limit the water consumption, especially in arid areas, the water may be recycled on the surface.
At some point, a propping agent is added to the liquid and inserted into the fracture. The propping agent, e.g. sand or ceramic beads, remains in the fracture when the injection pressure drops, and thereby keeps the fractures open. Fracturing or other stimulation may be repeated several times during the lifetime of a well, so there is a general need to reduce the cost of re-fracturing as much as possible.
Specifically, if the cost of re-fracturing is too high, the well may be abandoned even if the reservoir is not depleted. Similarly, if low-cost re-fracturing was available, several abandoned production wells might become profitable. Similar considerations apply to production start of marginal fields, to stimulation other than hydraulic fracturing and to injection wells. Thus, there is a need to reduce the cost of stimulating and re-stimulating a well.
When assessing the profitability of stimulation or re-stimulation, at least the following potential problems and shortcomings should be considered and accounted for:                any need for separate trips, i.e. inserting and retrieving a string once per target zone;        cost and/or availability of water and/or recycling process water;        high pressure injection at a target zone may force sand from the formation into the fractures and/or the wellbore at adjacent zones.        
Our co-pending patent application NO20150182A1 discloses an injection assembly that solves or reduces some of the problems and shortcomings above. Specifically, the injection assembly comprises a string with an upstream packer and a downstream packer for isolating a target zone, and a normally closed injection valve between the packers. A normally open bottom valve at the very end of the string allows fluid circulation during run in, and closes when an injection rate exceeds a preset level. Water, possibly with soluble additives, is used for the circulation. The return water typically contains sand and other solid particles, which are relatively easy to remove. Inexpensive recycling reduces water consumption and cost of operation. After injection, the apparatus is reset such that it can be moved to a new target zone where the process is repeated. Thus, several zones can be stimulated in one trip, which saves time and reduces operational costs.
The packers in the injection assembly are called “zone isolation packers” in the following to avoid confusion with packers that may be present uphole from the injection assembly.
In some applications, sand and gravel from the formation enters the annulus between the string and inner wall of the wellbore. The produced sand enters the annulus during or after stimulation, e.g. at the target zone when the injection pressure drops after stimulation. During stimulation, a high injection pressure may leak to regions of the wellbore away from the target zone. If the wellbore is open hole, i.e. uncased, or the casing has perforations in this region, produced sand may enter the annulus above the packers isolating the target zone during stimulation. Regardless of cause or path, produced sand in the annulus may prevent the string and injection assembly from moving to the next target zone or to the surface.
An objective of the present invention is to improve the injection assembly described above, in particular to reduce the effects of produced sand in the annulus around the string used for stimulating a target zone.